Methods for minimizing fluid loss to and determining the locations of lost circulation zones

ABSTRACT

A method for determining a location of a lost circulation zone in a wellbore having a first wellbore fluid therein that includes allowing loss of the first wellbore fluid to the lost circulation zone to stabilize; adding a volume of a second wellbore fluid having a density less than the first wellbore fluid to the wellbore on top of the first wellbore fluid to a predetermined wellbore depth; determining an average density of the combined first wellbore fluid and second wellbore fluid; mixing the first wellbore fluid and the second wellbore fluid together; pumping a volume of a third wellbore fluid having a density greater the average density of the combined first and second wellbore fluid into the wellbore bottom until fluid loss occurs; and determining the location of the lost circulation zone is disclosed.

BACKGROUND OF INVENTION

1. Field of the Invention

Embodiments disclosed herein relate generally to lost circulationexperienced during drilling a wellbore. In particular, embodimentsdisclosed herein relate to the identification or determination of thelocation(s) of loss zones in a wellbore for lost circulation treatments.

2. Background Art

During the drilling of a wellbore, various fluids are typically used inthe well for a variety of functions. The fluids may be circulatedthrough a drill pipe and drill bit into the wellbore, and then maysubsequently flow upward through the wellbore to the surface. Duringthis circulation, the drilling fluid may act to remove drill cuttingsfrom the bottom of the hole to the surface, to suspend cuttings andweighting material when circulation is interrupted, to controlsubsurface pressures, to maintain the integrity of the wellbore untilthe well section is cased and cemented, to isolate the fluids from theformation by providing sufficient hydrostatic pressure to prevent theingress of formation fluids into the wellbore, to cool and lubricate thedrill string and bit, and/or to maximize penetration rate.

Wellbore fluids may also be used to provide sufficient hydrostaticpressure in the well to prevent the influx and efflux of formationfluids and wellbore fluids, respectively. When the pore pressure (thepressure in the formation pore space provided by the formation fluids)exceeds the pressure in the open wellbore, the formation fluids tend toflow from the formation into the open wellbore. Therefore, the pressurein the open wellbore is typically maintained at a higher pressure thanthe pore pressure. While it is highly advantageous to maintain thewellbore pressures above the pore pressure, on the other hand, if thepressure exerted by the wellbore fluids exceeds the fracture resistanceof the formation, a formation fracture and thus induced mud losses mayoccur. Further, with a formation fracture, when the wellbore fluid inthe annulus flows into the fracture, the loss of wellbore fluid maycause the hydrostatic pressure in the wellbore to decrease, which may inturn also allow formation fluids to enter the wellbore. As a result, theformation fracture pressure typically defines an upper limit forallowable wellbore pressure in an open wellbore while the pore pressuredefines a lower limit. Therefore, a major constraint on well design andselection of drilling fluids is the balance between varying porepressures and formation fracture pressures or fracture gradients thoughthe depth of the well.

As stated above, wellbore fluids are circulated downhole to remove rock,as well as deliver agents to combat the variety of issues describedabove. Fluid compositions may be water- or oil-based and may compriseweighting agents, surfactants, proppants, and polymers. However, for awellbore fluid to perform all of its functions and allow wellboreoperations to continue, the fluid must stay in the borehole. Frequently,undesirable formation conditions are encountered in which substantialamounts or, in some cases, practically all of the wellbore fluid may belost to the formation. For example, wellbore fluid can leave theborehole through large or small fissures or fractures in the formationor through a highly porous rock matrix surrounding the borehole.

Lost circulation is a recurring drilling problem, characterized by lossof drilling mud into downhole formations. However, other fluids, besides“drilling fluid” can potentially be lost, including completion,drill-in, production fluid, etc. Lost circulation can occur naturally informations that are fractured, highly permeable, porous, cavernous, orvugular. These earth formations can include shale, sands, gravel, shellbeds, reef deposits, limestone, dolomite, and chalk, among others.

Lost circulation may also result from induced pressure during drilling.Specifically, induced mud losses may occur when the mud weight, requiredfor well control and to maintain a stable wellbore, exceeds the fractureresistance of the formations. A particularly challenging situationarises in depleted reservoirs, in which the drop in pore pressureweakens hydrocarbon-bearing rocks, but neighboring or inter-bedded lowpermeability rocks, such as shales, maintain their pore pressure. Thiscan make the drilling of certain depleted zones impossible because themud weight required to support the shale exceeds the fracture resistanceof the sands and silts. Another unintentional method by which lostcirculation can result is through the inability to remove low and highgravity solids from fluids. Without being able to remove such solids,the fluid density can increase, thereby increasing the hole pressure,and if such hole pressure exceeds the formation fracture pressure,fractures and fluid loss can result.

Losing any fluid to the formation, for any reason, can be a costlyresult for the drilling, completion, or production operation due to thefluid cost as well as the rig downtime and equipment rental. Mechanicaland electrical methods exist for determining the location(s) or zone(s)of fluid loss; however, they require specialized equipment and repeatedtrips in and out of the hole. If such equipment is unavailable, thelocation of the loss zones may not actually be determined but insteadlarger than necessary volumes of loss circulation treatments may bepumped into the well with the hope that the treatment will plug the zonewhere losses are occurring so that that drilling (or other) operationsmay resume. Because of this inaccuracy, it is typically necessary torepeat loss circulation treatments, further increasing costs anddowntime.

Accordingly, there exists a continuing need for methods by which a losszone may be easily and more accurately determined without the cost ofspecialized equipment so that a loss zone may be identified and pluggedmore quickly and the regular drilling or other operations resumed.

SUMMARY OF INVENTION

In one aspect, embodiments disclosed herein relate to a method fordetermining a location of a lost circulation zone in a wellbore having afirst wellbore fluid therein that includes allowing loss of the firstwellbore fluid to the lost circulation zone to stabilize; adding avolume of a second wellbore fluid having a density less than the firstwellbore fluid to the wellbore on top of the first wellbore fluid to apredetermined wellbore depth; determining an average density of thecombined first wellbore fluid and second wellbore fluid; mixing thefirst wellbore fluid and the second wellbore fluid together; pumping avolume of a third wellbore fluid having a density greater the averagedensity of the combined first and second wellbore fluid into thewellbore bottom until fluid loss occurs; and determining the location ofthe lost circulation zone.

In another aspect, embodiments disclosed herein relate to a method forminimizing fluid loss to a lost circulation zone in a wellbore having afirst wellbore fluid therein that includes allowing loss of the firstwellbore fluid to the lost circulation zone to stabilize; adding avolume of a second wellbore fluid having a density less than the firstwellbore fluid to the wellbore on top of the first wellbore fluid to apredetermined wellbore depth; determining an average density of thecombined first wellbore fluid and second wellbore fluid; and pumping athird wellbore having the determined average density of the combinedfirst and second wellbore fluids into the wellbore to fill the wellbore.

In yet another aspect, embodiments disclosed herein relate to a methodfor determining a location of a lost circulation zone in a wellborehaving a wellbore fluid therein that includes allowing loss of thewellbore fluid to the lost circulation zone to stabilize; calculatingthe pressure gradient of the lost circulation zone; increasing theweight of the wellbore fluid in the wellbore from a bottom of thewellbore upwards until fluid loss occurs; and calculating the locationof the lost circulation zone.

Other aspects and advantages of the invention will be apparent from thefollowing description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIGS. 1 to 6 show schematics of a wellbore having a lost circulationevent and subjected to the methods disclosed herein.

DETAILED DESCRIPTION

Embodiments disclosed herein generally relate to the identification ordetermination of the location(s) of loss zones in a wellbore. Inparticular, embodiments disclosed herein relate to determination of aloss circulation zone so that a lost circulation treatment may be moreaccurately placed in the vicinity of the loss.

In particular, the method of the present disclosure rely on theprinciples of pore pressures and pressure gradients within a well todetermine the location of a lost circulation zone instead of relying oncostly and time-consuming mechanical or electrical equipment to makesure determinations. Specifically, the methods described herein mayinclude determination of pressure gradients to achieve a balanced (orslightly overbalanced) well and then slowing introducing a heavierwellbore fluid at the wellbore bottomhole such that when the heavierfluid reaches the depth of the loss circulation zone, additional fluidloss will occur, indicating the location of the loss circulation zonehas been determined.

Referring to FIGS. 1 to 6, schematic illustrations of a wellbore atincremental stages of the methods disclosed herein are shown.Specifically, as shown in FIG. 1, a wellbore 10 includes a firstwellbore fluid 20 therein. Such wellbore fluid 20 may include any typeof wellbore fluid, including drilling fluids, completion fluids,drill-in fluids, production fluids, and the like, which may include oneor more liquid and/or gas phases. Rather, no limitation is placed on thetype of wellbore fluid that may be present in the wellbore when lostcirculation occurs, and the present methods may be applied to determinethe location of the lost circulation.

When a lost circulation event occurs, loss of first wellbore fluid 20 tothe formation at the lost circulation zone 16 occurs, and is identified,for example, a drop in the fluid level, by constant or periodic make-upvolumes, or the inability to maintain circulation of the wellbore fluid.Once a lost circulation event is detected, in accordance methodsdisclosed herein, pumping of the first wellbore fluid is stopped, andthe fluid level 20 a is allowed to decrease or stabilize to anequilibrium static point 12. Stabilization occurs when the formationpressure exerted on the loss circulation zone and the pressure exertedby the fluid in the wellbore are balanced (or at least substantiallybalanced).

Upon stabilization of the first wellbore fluid 20, a second wellborefluid 22 lighter than the first wellbore fluid 20 is added to the casingtop (i.e., on top of the first wellbore fluid 20) until the secondwellbore fluid level 20 a reaches a predetermined wellbore depth (whichas shown in FIG. 2, is a depth of zero, at the top of the casing. Asmentioned above with respect to first wellbore fluid 20, second wellborefluid (as well as any other wellbore fluids) may include at least oneliquid and/or gaseous component. In a particular embodiment, the secondwellbore fluid 26 may be water. The volume of second wellbore fluid 20added to the wellbore 10 is measured and recorded. When the secondwellbore fluid 20 is added to the wellbore 10, the first wellbore fluidlevel 20 a may drop to a greater depth D2 as compared to D1 due to theincreased density/fluid pressure added by the second wellbore fluid toobtain a pressure balanced system.

Upon stabilization of the fluids 20 and 22 within the wellbore andmeasurement/recordal of the volume of second wellbore fluid 22 added tothe well, the average fluid density between the combined first andsecond wellbore fluids 20 and 22 may be determined. Such determinationmay be made through calculating the fluid volume fractions, depthfractions well fractions, total pressure within the wellbore, and/oraverage fluid gradient density. However, one skilled in the art wouldappreciate that the ultimate determination (average fluid density) maybe broken into multiple calculation steps or may be performed as asingle long calculation.

Upon determination of the average density for the balanced wellborefluid system in the wellbore (layers of wellbore fluids 20 and 22), thefluids may be mixed/homogenized or displaced (with a third wellborefluid) such that the fluid 24 present in the wellbore 10 is asubstantially uniform fluid having a density at the calculated density(of the first and second wellbore fluids 20 and 22) so that the wellremains balanced (or even slightly overbalanced for safety concerns).Depending on the intent of the operator, drilling may be continued atthis density or the location of the lost circulation zone may bedetermined. Drilling may be continued without making such determinationin such an instance where the operator does not care to determine thelocation of the lost circulation zone, but instead desires to determinethe maximum density of the wellbore fluid that may be used to continuedrilling with minimal fluid losses.

However, if the operator wishes to determine the location of the lostcirculation zone, once the well has a fluid density substantiallybalancing the wellbore's pressure gradient, a fourth wellbore fluid 26may be pumped into and fill the drill string. Fourth wellbore fluid 26may have a density slightly greater than the balanced wellbore fluid 24.Such increase in density may be achieved by formulating a fluid 26having a density greater than the average density of the first andsecond wellbore fluids 20 and 22 (through general fluid components,including weight material) and/or adding a weight material to the athird displacement fluid 24 (if used). The amount of such increase indensity (as compared to balanced fluid 24) may be selected based on theparticular well; however, suitable ranges may include an increase of atleast 0.5 ppg in some embodiments and at least 1.0 ppg in otherembodiments. However, no limitation is intended on the scope of thepresent disclosure. Rather other density differentials may be usedwithout departing from the scope of the present disclosure.

Pumping of fluid 26 out of the drill string and into the wellbore 10occurs at a slow rate, and by measuring the pump strokes so that thevolume of fourth wellbore fluid 26 may be recorded. Additionally,pumping may occur at a slow rate, and with periodic stops so that fluidloss may be detected as soon as possible after occurrence. As shown inFIG. 5, no fluid loss to the formation 18 has occurred because thedensity of fluid 24 above the low pressure pore area at the lostcirculation zone 16 is the same as the pressure exerted by the fluidabove the zone. However, as shown in FIG. 6, fluid loss occurs becauseas the volume of fluid 26 pumped into the wellbore increases such thatthe fluid level 26 a approaches the lost circulation zone 16, the denserfluid 26 is exerting greater pressure on the lost circulation zone 16than what the formation is exerting on the wellbore fluid 24. As soon asfluid loss is detected, the measurement of the volume of fluid 26 pumpedinto the wellbore (as it is pumped from the bottom of the wellbore up)may be used to determine the depth D3 or location of lost circulationzone 16 using known wellbore dimensional values.

However, it is possible that a single wellbore 10 may include multiplelost circulation zones 16. In such an instance, the lost circulationzones may be determined from the bottom of the well up, repeating thesteps described herein until each lost circulation zone is locationallyindentified and treated.

Following determination of the location(s) of the lost circulation zone16, a lost circulation treatment may be accurately placed proximate thelocation of the loss zone. Lost circulation treatments fall into twomain categories: low fluid loss treatments where the fracture orformation is rapidly plugged and sealed; and high fluid loss treatmentswhere dehydration of the loss prevention material in the fracture orformation with high leak off of a carrier fluid fills a fracture and/orforms a plug that then acts as the foundation for fracture sealing. Themechanism by which fluid loss is controlled, i.e., plugging, bridging,and filling, may be based on the particle size distribution, relativefracture aperture, fluid leak-off through the fracture walls, and fluidloss to the fracture tip. Accurate placement of such materials may allowfor less rigdown downtime and more managed use of lost circulationtreatments. Selection of lost circulation treatments may be made basedon the type quantification, and analysis of losses, formation/fracturetype, and pressures within the loss zone, many of which may bequantified during the methods disclosed herein. Selection based on thesefactors may be described in greater detail in U.S. Patent ApplicationNo. 61/024,807, which is assigned to the present assignee and hereinincorporated by reference in its entirety.

Lost circulation treatments may include particulate- and/orsettable-based treatments. Particulate-based treatments may include useof particles frequently referred to in the art as bridging materials.For example, such bridging materials may include at least onesubstantially crush resistant particulate solid such that the bridgingmaterial props open and bridges or plugs the fractures (cracks andfissures) that are induced in the wall of the wellbore. Examples ofbridging materials suitable for use in the present disclosure includegraphite, calcium carbonate (preferably, marble), dolomite(MgCO₃.CaCO₃), celluloses, micas, proppant materials such as sands orceramic particles and combinations thereof. In addition to suchparticulate based treatments, depending on the classified severity ofloss, a reinforcing plug, including cement- or resin-based plugs, may benecessary to seal off the fracture.

Settable treatments suitable for use in the methods of the presentdisclosure include those that may set or solidify upon a period of time.The term “settable fluid” as used herein refers to any suitable liquidmaterial which may be pumped or emplaced downhole, and will harden overtime to form a solid or gelatinous structure and become more resistanceto mechanical deformation. Examples of compositions that may be includedin the carrier fluid to render it settable include cementious materials,“gunk” and polymeric or chemical resin components.

Further, while the present disclosure may refer to use of these methodsin traditional wellbores and/or traditional drilling operations, thepresent invention is not so limited. Rather, it is specifically withinthe scope of the present invention that the methods disclosed herein maybe used in any wellbore operations, including, for example, casingdrilling, cable drilling, conventional drilling, reverse circulationdrilling, and coiled tubing drilling, etc.

Example

The following example is used to demonstrate the manner in which thedepth of a lost circulation zone may be calculated and a treatment morerapidly and accurately spotted into the well.

For a given well (such as that shown in FIG. 1) that has an observedfluid loss of an original wellbore fluid (11 ppg), the fluid loss may beallowed to stabilize. Following stabilization, a light density fluid(water, 8.334 ppg) may be added to the top of the well, as shown in FIG.2, and the volume of light density fluid added to the well to fill thewell to a predetermined depth (i.e., zero depth) is recorded (as shownin Table 1 below). From the volume of lighter density fluid (3400gallons), the casing and drill pipe diameter, the volume per depth (anddepth) of the light density fluid may be calculated. Thus, by knowingthe total footage drilled, the well fractions of the original and lightdensity fluid, as well as the total pressure along the wellbore, may becalculated. From this pressure value, the average fluid gradient (10.079ppg) is calculated.

TABLE 1 Calculate Pressure Gradient as Fluid Weight #1 Original FluidDensity* 11 pounds per gallon #2 Light Density Fluid* 8.334 pounds pergallon Volume of Light Density Fluid Added #2* 3400 Gallons InternalDiameter of Casing* 9.625 Inches External Diameter of Drill Pipe* 3.5Inches Casing Volume/depth*** 3.2811 gallons per foot Calculated Depthof Light Fluid Added*** 1036.2 Feet of Light Density Fluid Total WellTVD* 3000 Feet Well Fraction of Original Fluid Density*** 1123.3 psifraction Well Fraction of Light Density Fluid*** 449.07 psi fractionTotal pressure along wellbore*** 1572.3 psi at bottom of hole Averagefluid gradient density*** 10.079 pounds per gallon Required *= Data ***=Calculated Data

Following mixing of the original and light density fluid to form ahomogenous fluid (10.079 ppg a weight material (at +1 ppg) may be addedto the fluid to form a heavier fluid. The heavier fluid may be filledinto the drill string and slowly pumped at the borehole bottom. Pumpstrokes may be calculated, and the pumping periodically stopped so thatfluid levels may be observed and fluid loss immediately detected. Upondetection of fluid loss, the number of pump strokes and/or volume offluid pumped into the wellbore may be recorded. From the volume ofheavier fluid pumped into the wellbore (as well as drill pipe and bitdiameter), the volume per depth, as well as total feet from thebottomhole, of the heavier fluid may be calculated. The lost circulationzone will correspond to the heavier fluid height. From the heavier fluidheight, the depth from the surface may be calculated so that a lostcirculation treatment may be spotted with relative accuracy.

Embodiments of the present disclosure may advantageously provide for atleast one of the following. Losing any fluid to the formation, for anyreason, can be a costly result for the drilling, completion, orproduction operation due to the fluid cost as well as the rig downtimeand equipment rental. Conventional reactions include use of eithermechanical and electrical equipment (with repeated trips in and out ofthe hole) or larger than necessary volumes of loss circulationtreatments may be pumped into the well with the hope that the treatmentwill plug the zone where losses are occurring so that that drilling (orother) operations may resume. Because of this inaccuracy, it istypically necessary to repeat loss circulation treatments, furtherincreasing costs and downtime. However, in accordance with the presentdisclosure, methods by which a loss zone may be easily and moreaccurately determined are provided without the cost of specializedequipment so that a loss zone may be identified and plugged more quicklyand the regular drilling or other operations resumed.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

1. A method for determining a location of a lost circulation zone in awellbore having a first wellbore fluid therein, comprising: allowingloss of the first wellbore fluid to the lost circulation zone tostabilize; adding a volume of a second wellbore fluid having a densityless than the first wellbore fluid to the wellbore on top of the firstwellbore fluid to a predetermined wellbore depth; determining an averagedensity of the combined first wellbore fluid and second wellbore fluid;mixing the first wellbore fluid and the second wellbore fluid together;pumping a volume of a third wellbore fluid having a density greater theaverage density of the combined first and second wellbore fluid into thewellbore bottom until fluid loss occurs; and determining the location ofthe lost circulation zone.
 2. The method of claim 1, further comprising:pumping a lost circulation treatment into the determined location of thelost circulation zone.
 3. The method of claim 1, wherein the thirdwellbore fluid has a density of at least 0.5 ppg more than the averagedensity of the combined first and second wellbore fluid.
 4. The methodof claim 1, wherein the pumping the volume of third wellbore comprises:pumping the third wellbore fluid to a bottom of a drilling assembly; andpumping and measuring pump strokes as the third wellbore fluid exits thebottom of the drilling assembly until fluid loss is detected and pumpingis halted.
 5. The method of claim 1, further comprising: identifyingloss of the first wellbore fluid to the loss circulation zone.
 6. Themethod of claim 5, further comprising: stopping pumping of the firstwellbore fluid into the wellbore.
 7. The method of claim 1, furthercomprising: determining a location of a second loss circulation zone inthe wellbore.
 8. The method of claim 1, wherein the mixing comprisesforming a homogenous blend of the first and second wellbore fluids.
 9. Amethod for minimizing fluid loss to a lost circulation zone in awellbore having a first wellbore fluid therein, comprising: allowingloss of the first wellbore fluid to the lost circulation zone tostabilize; adding a volume of a second wellbore fluid having a densityless than the first wellbore fluid to the wellbore on top of the firstwellbore fluid to a predetermined wellbore depth; determining an averagedensity of the combined first wellbore fluid and second wellbore fluid;and pumping a third wellbore having the determined average density ofthe combined first and second wellbore fluids into the wellbore to fillthe wellbore.
 10. The method of claim 9, further comprising: drillingwith the third wellbore fluid having the determined average density. 11.The method of claim 9, further comprising: pumping a third wellborehaving the average density of the combined first and second wellborefluids into the wellbore to fill the wellbore; pumping a volume offourth wellbore fluid having a density greater the average density ofthe combined first and second wellbore fluid into the wellbore bottomuntil fluid loss occurs; and determining the location of the lostcirculation zone.
 12. The method of claim 11, further comprising:pumping a lost circulation treatment into the determined location of thelost circulation zone.
 13. The method of claim 11, wherein the fourthwellbore fluid has a density of at least 0.5 ppg more than the averagedensity of the combined first and second wellbore fluid.
 14. The methodof claim 11, wherein the pumping the volume of fourth wellborecomprises: pumping the fourth wellbore fluid to a bottom of a drillingassembly; and pumping and measuring pump strokes as the fourth wellborefluid exits the bottom of the drilling assembly until fluid loss isdetected and pumping is halted.
 15. The method of claim 9, furthercomprising: identifying loss of the first wellbore fluid to theformation.
 16. The method of claim 9, further comprising: stoppingpumping of the first wellbore fluid into the wellbore.
 17. The method ofclaim 11, further comprising: determining a location of a second losscirculation zone in the wellbore.
 18. The method of claim 9, wherein thepumping the third wellbore fluid comprises displacing the first andsecond wellbore fluids from the wellbore.
 19. A method for determining alocation of a lost circulation zone in a wellbore having a wellborefluid therein, comprising: allowing loss of the wellbore fluid to thelost circulation zone to stabilize; calculating the pressure gradient ofthe lost circulation zone; increasing the weight of the wellbore fluidin the wellbore from a bottom of the wellbore upwards until fluid lossoccurs; and calculating the location of the lost circulation zone. 20.The method of claim 17, further comprising: pumping a lost circulationtreatment into the determined location of the lost circulation zone. 21.The method of claim 17, wherein calculating the pressure gradientcomprises determining a wellbore fluid density that balances or slightlyoverbalances the pressure gradient.
 22. The method of claim 17, whereinthe fluid loss stabilizes when the pore pressure and the fluid pressureare substantially the same.